Invert drilling fluids and methods of drilling boreholes

ABSTRACT

Methods for drilling, running casing in, and/or cementing a borehole in a subterranean formation without significant loss of drilling fluid are disclosed, as well as compositions for use in such methods. The methods employ drilling fluids comprising fragile gels or having fragile gel behavior and providing superior oil mud rheology and overall performance. The fluids are especially advantageous for use in offshore wells because the fluids exhibit minimal differences between downhole equivalent circulating densities and surface densities notwithstanding differences in drilling or penetration rates. When an ester and isomerized olefin blend is used for the base of the fluids, the fluids make environmentally acceptable and regulatory compliant invert emulsion drilling fluids.

RELATED APPLICATIONS

This application is a continuation of U.S. patent application Ser. No.10/292,124, filed Nov. 12, 2002, pending, which is acontinuation-in-part of U.S. Pat. No. 6,887,832, issued May 3, 2005,which is a continuation-in-part of U.S. patent application Ser. No.09/929,465, filed Aug. 14, 2001, abandoned, and International PatentApplication Nos. PCT/US00/35609 and PCT/US00/35610, both filed Dec. 29,2000, and having entered national phase in the United States and pendingas U.S. patent application Ser. No. 10/432,787 and U.S. patentapplication Ser. No. 10/432,786 respectively.

BACKGROUND OF THE INVENTION 1. Field of the Invention

The present invention relates to compositions and methods for drilling,cementing and casing boreholes in subterranean formations, particularlyhydrocarbon bearing formations. More particularly, the present inventionrelates to oil or synthetic fluid based drilling fluids and fluidscomprising invert emulsions, such as fluids using esters for example,which combine high ecological compatibility with good stability andperformance properties. 2. Description of Relevant Art

A drilling fluid or mud is a specially designed fluid that is circulatedthrough a wellbore as the wellbore is being drilled to facilitate thedrilling operation. The various functions of a drilling fluid includeremoving drill cuttings from the wellbore, cooling and lubricating thedrill bit, aiding in support of the drill pipe and drill bit, andproviding a hydrostatic head to maintain the integrity of the wellborewalls and prevent well blowouts. Specific drilling fluid systems areselected to optimize a drilling operation in accordance with thecharacteristics of a particular geological formation.

Oil or synthetic fluid-based muds are normally used to drill swelling orsloughing shales, salt, gypsum, anhydrite or other evaporate formations,hydrogen sulfide-containing formations, and hot (greater than about 300degrees Fahrenheit (“° F.”) holes, but may be used in other holespenetrating a subterranean formation as well. Unless indicatedotherwise, the terms “oil mud” or “oil-based mud or drilling fluid”shall be understood to include synthetic oils or other synthetic fluidsas well as natural or traditional oils, and such oils shall beunderstood to comprise invert emulsions.

Oil-based muds used in drilling typically comprise: a base oil (orsynthetic fluid) comprising the external phase of an invert emulsion; asaline, aqueous solution (typically a solution comprising about 30%calcium chloride) comprising the internal phase of the invert emulsion;emulsifiers at the interface of the internal and external phases; andother agents or additives for suspension, weight or density,oil-wetting, fluid loss or filtration control, and rheology control.Such additives commonly include organophilic clays and organophiliclignites. See H. C. H. Darley and George R. Gray, Composition andProperties of Drilling and Completion Fluids 66-67, 561-562 (5^(th) ed.1988). An oil-based or invert emulsion-based drilling fluid may commonlycomprise between about 50:50 to about 95:5 by volume oil phase to waterphase. An all oil mud simply comprises 100% liquid phase oil by volume;that is, there is no aqueous internal phase.

Invert emulsion-based muds or drilling fluids (also called invertdrilling muds or invert muds or fluids) comprise a key segment of thedrilling fluids industry. However, increasingly invert emulsion-baseddrilling fluids have been subjected to greater environmentalrestrictions and performance and cost demands. There is consequently anincreasing need and industry-wide interest in new drilling fluids thatprovide improved performance while still affording environmental andeconomical acceptance.

SUMMARY OF THE INVENTION

The present invention provides improved methods of drilling wellbores insubterranean formations employing oil-based muds, or more particularly,invert emulsion-based muds or drilling fluids. As used herein, the term“drilling” or “drilling wellbores” shall be understood in the broadersense of drilling operations, which include running casing and cementingas well as drilling, unless specifically indicated otherwise. Thepresent invention also provides invert emulsion based drilling fluidsfor use in the methods of the invention to effect the advantages of theinvention.

The methods of the invention comprise using a drilling fluid that is notdependent on organophilic clays (also called “organo-clays”) to obtainsuspension of drill cuttings or other solids. Rather, the drilling fluidcomprises a synergistic combination of an invert emulsion base,thinners, and/or other additives that form a “fragile gel” or show“fragile gel” behavior when used in drilling. The fragile gel structureof the drilling fluid is believed to provide or enable suspension ofdrill cuttings and other solids.

The fragile gel drilling fluids of the invention, for use in the methodsof the invention, are characterized by their performance. When drillingis stopped while using a fluid of the invention, and consequently whenthe stresses or forces associated with drilling are substantiallyreduced or removed, the drilling fluid acts as a gel,suspending/continuing to suspend drill cuttings and other solids (suchas for example weighting materials) for delivery to the well surface.Nevertheless, when drilling is resumed, the fluid is flowable, actinglike a liquid, with no appreciable or noticeable pressure spike asobserved by pressure-while-drilling (PWD) equipment or instruments.During drilling, the fluids of the invention generally maintainconsistently low values for the difference in their surface density andtheir equivalent density downhole (ECDs) and show significantly reducedloss when compared to other drilling fluids used in that formation orunder comparable conditions. “Sag” problems do not tend to occur withthe fluids when drilling deviated wells. The phenomenon of “sag,” or“barite sag” is discussed below. Also, the fluids respond quickly to theaddition of thinners, with thinning of the fluids occurring soon afterthe thinners are added, without need for multiple circulations of thefluids with the thinners additive or additives in the wellbore to showthe effect of the addition of the thinners. The fluids of the inventionalso yield flatter profiles between cold water and downhole rheologies,making the fluids advantageous for use in offshore wells. That is, thefluids may be thinned at cold temperatures without causing the fluids tobe comparably thinned at higher temperatures.

Laboratory tests may be used to generally identify or distinguish adrilling fluid of the invention. These tests measure elastic modulus andyield point and are generally conducted on laboratory-made fluids havingan oil:water ratio of about 70:30. Generally, a fluid of the presentinvention at these laboratory conditions/specifications will have anelastic modulus ratio of G′₁₀/G′₂₀₀ (as defined herein) greater thanabout 2. Furthermore, a fluid of the present invention at theselaboratory conditions/specifications will have a yield point (measuredas described herein) of less than about 3 Pa.

Another test, useful for distinguishing a drilling fluid of theinvention using field mud samples, is a performance measure called“Stress Build Function.” This measure is an indication of the fragilegel structure building tendencies that are effectively normalized forthe initial yield stress (Tau0). The “Stress Build Function” is definedas follows:SBF10m=(gel strength at 10 minutes−Tau0)/Tau0Generally, a field mud of the present invention will have an SBF10m ofgreater than about 3.8.

Although the invention is characterized primarily as identifyingcharacteristics or features of an invert emulsion drilling fluid thatyield superior performance for use in drilling, certain examplecompositions also provide significant benefits in terms of environmentalacceptance or regulatory compliance. An example of a suitable base is ablend of esters with isomerized or internal olefins (“the ester blend”)as described in U.S. patent application Ser. No. 09/929,465, of JeffKirsner (co-inventor of the present invention), Kenneth W. Pober andRobert W. Pike, filed Aug. 14, 2001, entitled “Blends of Esters withIsomerized Olefins and Other Hydrocarbons as Base Oils for InvertEmulsion Oil Muds, the entire disclosure of which is incorporated hereinby reference. The esters in the blend may be any quantity, butpreferably should comprise at least about 10 weight percent to about 99weight percent of the blend and the olefins should preferably compriseabout 1 weight percent to about 99 weight percent of the blend. Theesters of the blend are preferably comprised of fatty acids and alcoholsand most preferably about C₆ to about C₁₄ fatty acids and 2-ethylhexanol. Esters made in ways other than with fatty acids and alcohols,for example, esters made from olefins combined with either fatty acidsor alcohols, could also be effective.

Further, such environmentally acceptable examples of invert emulsiondrilling fluids have added to or mixed with them other fluids ormaterials needed to comprise a complete drilling fluid. Such materialsmay include, for example: additives to reduce or control temperaturerheology or to provide thinning, for example, additives having thetradenames COLDTROL®, ATC®, and OMC2™; additives for enhancingviscosity, for example, an additive having the tradename RHEMOD L™;additives for providing temporary increased viscosity for shipping(transport to the well site) and for use in sweeps, for example, anadditive having the tradename TEMPERUS™ (modified fatty acid); additivesfor filtration control, for example, additives having the tradenameADAPTA®; additives for high temperature high pressure control (HTHP) andemulsion stability, for example, additives having the tradename FACTAN®(highly concentrated tall oil derivative); and additives foremulsification, for example, additives having the tradename LE SUPERMUL™(polyaminated fatty acid). All of the aforementioned trademarkedproducts are available from Halliburton Energy Services, Inc. inHouston, Tex., U.S.A.

Thinners disclosed in International Patent Application Nos.PCT/US00/35609 and PCT/US00/35610 of Halliburton Energy Services, Inc.,Cognis Deutschland GmbH & Co KG., Heinz Muller, Jeff Kirsner(co-inventor of the present invention) and Kimberly Burrows (co-inventorof the present invention), both filed Dec. 29, 2000 and entitled“Thinners for Invert Emulsions,” and both disclosures of which areincorporated entirely herein by reference, are particularly useful inthe present invention for effecting “selective thinning” of the fluid ofthe present invention; that is thinning at lower temperatures withoutrendering the fluid too thin at higher temperatures.

However, as previously noted, preferably no organophilic clays are addedto the drilling fluid for use in the invention. Any characterization ofthe drilling fluid herein as “clayless” shall be understood to meanlacking organophilic clays. Although omission of organophilic clays is aradical departure from traditional teachings respecting preparation ofdrilling fluids, this omission of organophilic clays in preferredembodiments of the present invention allows the drilling fluid to havegreater tolerance to drill solids (i.e., the properties of the fluid arenot believed to be readily altered by the drill solids or cuttings) andis believed (without limiting the invention by theory) to contribute tothe fluid's superior properties in use as a drilling fluid.

BRIEF DESCRIPTION OF THE DRAWINGS

FIGS. 1(a), 1(b) and 1(c) provide three graphs showing field datacomparing fluid losses incurred during drilling, running casing andcementing with a prior art isomerized olefin fluid and with a fluid ofthe present invention. FIG. 1(a) shows the total downhole losses; FIG.1(b) shows the barrels lost per barrel of hole drilled; and FIG. 1(c)shows the barrels lost per foot.

FIG. 2 is a graph comparing fluid loss incurred running casing andcementing in seven boreholes at various depths, where the fluid used inthe first three holes was a prior art isomerized olefin fluid and thefluid used in the last four holes was a fluid of the present invention.

FIG. 3 is a graph indicating “fragile gel” formation in fluids of thepresent invention and their response when disrupted compared to someprior art isomerized olefin fluids.

FIG. 4 is a graph comparing the relaxation rates of various prior artdrilling fluids and fluids of the present invention.

FIG. 5(a) is a graph comparing the differences in well surface densityand the equivalent circulating density for a prior art isomerized olefinfluid and for a fluid of the invention in two comparable wells. FIG.5(b) shows the rate of penetration in the wells at the time the densitymeasurements for FIG. 5(a) were being taken.

FIG. 6 is a graph comparing the differences in well surface density andthe equivalent circulating density for a fluid of the invention with aflowrate of 704 to 811 gallons per minute in a 12¼ inch borehole drilledfrom 9,192 ft to 13,510 ft in deep water and including rate ofpenetration.

FIG. 7 is a graph comparing the differences in well surface density andthe equivalent circulating density for a fluid of the invention with aflowrate of 158 to 174 gallons per minute in a 6½ inch borehole drilledfrom 12,306 ft to 13,992 ft and including rate of penetration.

FIG. 8 is a graph comparing the differences in well surface density andthe equivalent circulating density for a fluid of the invention atvarying drilling rates from 4,672 ft to 12,250 ft, and a flowrate of 522to 586 gallons per minute in a 9⅞″ borehole.

FIG. 9(a) is a bar graph comparing the yield point of two densities of afluid of the invention at standard testing temperatures of 40° F. and120° F. FIGS. 9(b) and (c) are graphs of the FANN® 35 instrument dialreadings for these same two densities of a fluid of the invention over arange of shear rates at standard testing temperatures of 40° F. and 120°F.

FIG. 10 is a graph comparing the viscosity of various known invertemulsion bases for drilling fluids with the invert emulsion base for adrilling fluid of the present invention.

FIG. 11 is a graph showing the Stress Build Function for several priorart field muds compared to the Stress Build Function for a field sampleof a fluid of the present invention.

FIG. 12 is a graph showing bioassay results for a 96-hour sedimenttoxicity test with Leptocheirus plumulosus, comparing a referenceinternal olefin to laboratory and field mud samples of the ACCOLADE™system.

DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS

The present invention provides an invert drilling fluid that meetsenvironmental constraints and provides improved performance in thefield. The fluid does not rely on organophilic clays to obtainsuspension of barite or drill cuttings, in contrast to other fluids usedcommercially today. Some of the other characteristics that furtherdistinguish the fluid of the present invention from prior art invertfluids are: (1) lack of noticeable or significant pressure spikes (asdetected for example with pressure-while-drilling or PWD equipment orinstruments) when resuming pumping after a period of rest duringdrilling; (2) rapid incorporation of additives while pumping; (3) littleor no sag of barite or other solids, including drill cuttings; (4)reduction in fluid losses during drilling; and (5) low ECDs. Thesecharacteristics will be further explained and discussed below.

The distinctive characteristics of the fluid of the present inventionare believed to be due to a synergistic combination of base oilscomprising the fluid. Without limiting the invention by theory, thecombination is believed to have the effect of forming a “fragile gel.” A“gel” may be defined a number of ways. One definition indicates that a“gel” is a generally colloidal suspension or a mixture of microscopicwater particles (and any hydrophilic additives) approximately uniformlydispersed through the oil (and any hydrophobic additives), such that thefluid or gel has a generally homogeneous gelatinous consistency. Anotherdefinition states that a “gel” is a colloid in a more solid form than a“sol” and defines a “sol” as a fluid colloidal system, especially one inwhich the continuous phase is a liquid. Still another definitionprovides that a “gel” is a colloid in which the disperse phase hascombined with the continuous phase to produce a viscous jelly-likeproduct. Generally, a gel has a structure that is continually building.If the yield stress of a fluid increases over time, the fluid hasgelled. “Yield stress” is the stress required to be exerted to initiatedeformation.

A “fragile gel” as used herein is a “gel” that is easily disrupted orthinned, and that liquifies or becomes less gel-like and moreliquid-like under stress, such as caused by moving the fluid, but whichquickly returns to a gel or gel-like state when the movement or otherstress is alleviated or removed, such as when circulation of the fluidis stopped, as for example when drilling is stopped. The “fragileness”of the “fragile gels” of the present invention contributes to the uniqueand surprising behavior and advantages of the present invention. Thegels are so “fragile” that it is believed that they may be disrupted bya mere pressure wave or a compression wave during drilling. They breakinstantaneously when disturbed, reversing from a gel back into a liquidform with minimum pressure, force and time and with less pressure, forceand time than known to be required to convert prior art fluids from agel-like state into a flowable state.

In contrast, conventional drilling fluids, using clays to achievesuspension of solids (such as barite and drill cuttings) are believed tohave linked or interlinked clay particles providing structure. That is,organo-clays, which are typically formed from montmorillonite treatedwith a di-alkyl cationic surfactant, swell in non-polar organicsolvents, forming open aggregates. This structure, combined with thevolume occupied by water droplets is believed to be the main suspendingmechanism for barite and other inorganic materials in conventionalinvert drilling fluids. Mixing additives into the oil/clay suspendedsystem is slower than mixing additives into drilling fluids of theinvention.

The drilling fluids of the invention respond quickly to the addition ofthinners, with thinning of the fluids occurring soon after the thinnersare added, without need for multiple circulations of the fluids with thethinners additive or additives in the wellbore to show the effect of theaddition of the thinners. This characteristic provides the drillingoperator with the ability to control the fluid rheology “on-the-fly” and“on-command” from the wellbore surface, facilitating control of fluidrheological properties real time. Also, once returned to the surface,the thinner can be used to help separate the solids or drill cuttingsfrom the drilling fluid. This same drilling fluid, after its base fluidhas been replenished with requisite additives for fragile gel behavior,can be recycled back into the well for additional drilling. This abilityfor recycling provides another important advantage of the invention withrespect to minimizing disposal costs and environmental issues related tofluid disposal.

The drilling fluids of the invention also yield flatter profiles betweencold water and downhole rheologies, making the fluids advantageous foruse in deep water wells. That is, the fluids may be thinned at coldtemperatures without causing the fluids to be comparably thinned athigher temperatures. As used herein, the terms “deep water” with respectto wells and “higher” and “lower” with respect to temperature arerelative terms understood by one skilled in the art of the oil and gasindustry. However, generally, as used herein, “deep water wells” refersto any wells at water depths greater than about 1500 feet deep, “highertemperatures” means temperatures over about 120° F. and “lowertemperatures” means temperatures at about 40° F. to about 60° F.Rheology of a drilling fluid is typically measured at about 120° F. orabout 150° F.

Another distinctive and advantageous characteristic or feature of thedrilling fluids of the invention is that sag does not occur or does notsignificantly occur when the fluids are used in drilling deviated wells.Suspensions of solids in non-vertical columns are known to settle fasterthan suspensions in vertical ones, due to the “Boycott effect.” Thiseffect is driven by gravity and impeded by fluid rheology, particularlynon-Newtonian and time dependent rheology. Manifestation of the Boycotteffect in a drilling fluid is known as “sag.” Sag may also be describedas a “significant” variation in mud density (>0.5 to 1 pound per gallon) along the mud column, which is the result of settling of the weightingagent or weight material and other solids in the drilling fluid. Sag canresult in formation of a bed of the weighting agent on the low side ofthe wellbore, and stuck pipe, among other things. In some cases, sag canbe very problematic to the drilling operation and in extreme cases maycause hole abandonment.

The fragile gel nature of the invention also contributes to the reducedloss of drilling fluid observed in the field when using the fluid and tothe relatively low “ECDs” obtained with the fluid. The difference in adrilling fluid's measured surface density at the well head and thedrilling fluid's equivalent circulating density downhole (as typicallymeasured during drilling by downhole pressure-while-drilling (PWD)equipment) is often called “ECD” in the industry. Low “ECDs”, that is, aminimal difference in surface and downhole equivalent circulatingdensities, is critical in drilling deep water wells and other wellswhere the differences in subterranean formation pore pressures andfracture gradients are small.

Three tests may be used to distinguish drilling fluids of the inventionfrom clay-suspended. (i.e., traditional) fluids. Two of these tests areconducted with laboratory prepared fluids and the third test isconducted with samples of field muds-fluids that have already been usedin the field. The two tests with laboratory fluids concern measurementof elastic modulus and yield point and apply to lab-made fluids having avolume ratio of 70/30 oil/water. Generally, drilling fluids of thepresent invention at these laboratory conditions/specifications willhave an elastic modulus ratio of G′₁₀/G′₂₀₀ greater than about 2 and ayield point less than about 3 Pa. These tests are discussed furtherbelow using an example drilling fluid of the invention. The exampledrilling fluid, tradename ACCOLADE™, is available from HalliburtonEnergy Services, Inc. in Houston, Tex.

Test 1: Ratio of G′₁₀/G′₂₀₀.

Table 1 provides data taken with smooth parallel plate geometry. Theelastic modulus (G′) was measured using 35 mm parallel plate geometry ata separation of 1 mm on a Haake RS 150 controlled stress rheometer. Theapplied torque was <1 Pa, inside the linear viscoelastic region for eachsample. The elastic modulus was measured after 10 seconds (G′₁₀) andafter 200 seconds (G′₂₀₀), and the ratio of G′₁₀/G′₂₀₀ is shown inTable 1. All the samples in Table 1 were of drilling fluids having 11.0pounds per gallon (“ppg” or “lb./gal.”) total density and a base oil:water volume ratio of 70:30. TABLE 1 Ratios of G′₁₀/G′₂₀₀ for variousdrilling fluids 11.0 ppg Oil:water of 70:30 INVERMUL ® ENVIROMUL ™PETROFREE ® PETROFREE ® ACCOLADE ™ Diesel oil Paraffin oil PETROFREE ®SF LV Ratio 24 1.0 0.75 1.0 1.0 1.0 G′₁₀/ G′₂₀₀Similar data were found for an ACCOLADE™ fluid of 14.0 ppg, for whichG′₁₀/G′₂₀₀ was 4.2Test 2: Yield points.

The drilling fluids of the invention have an unusually low yield point,measured at low shear rate. The yield point in this test is the torquerequired to just start a system moving from rest. This point is selectedfor the measurement because low shear rates remove inertial effects fromthe measurement and are thus a truer measure of the yield point thanmeasurements taken at other points. The Haake RS 150 rheometer measuredthe yield point (τ in units of Pascals, Pa) as the shear rate increasedthrough 0.03, 0.1, 1.0, 3.0 and 10.0 s⁻¹. It was found that τ increasedwith shear rate, and the value at 0.03 s⁻¹ was taken as the true yieldpoint.

The program for measurement was as follows:

-   a) steady shear at 10 s⁻¹ for 30 seconds;-   b) zero shear for 600 seconds;-   c) steady shear at 0.03 s⁻¹ for 60 seconds—take the highest torque    reading;-   d) zero shear for 600 seconds;-   e) steady shear at 0.1 s⁻¹ for 60 seconds—take the highest torque    reading;-   f) zero shear for 600 seconds;-   g) steady shear at 1.0 s⁻¹ for 60 seconds—take the highest torque    reading;-   h) zero shear for 600 seconds;-   i) steady shear at 3.0 s⁻¹ for 60 seconds—take the highest torque    reading;-   j) zero shear for 600 seconds; and-   k) steady shear at 10 s⁻¹ for 60 seconds—take the highest torque    reading.

The measuring geometry was a 3 mm diameter stainless steel serratedplate, made by Haake with 26 serrations per inch, each serration 0.02inches deep. As expected the maximum value of the torque to startshearing, as shown in Table 2, increased with shear rate and the valueat the lowest shear rate (0.03 s⁻¹) was taken as the yield point. Alldrilling fluids in Table 2 were 11.0 ppg with 70/30 oil/water volumeratio. TABLE 2 Maximum torque (Pa) at increasing shear rates ACCOLADE™PETROFREE ® PETROFREE ® mixed LV SF Max τ (Pa) at a ester/internalPETROFREE ® low viscosity internal-olefin shear rate olefin ester esterbase τ @ 0.03 s⁻¹ 1.6 12.7 6.6 3.0 τ @ 0.1 s⁻¹ 2.0 13.1 7.4 4.4 τ @ 1.0s⁻¹ 2.7 17.8 8.7 6.6 τ @ 3.0 s⁻¹ 2.9 19.1 9.5 7.3 τ @ 10.0 s⁻¹ 3.3 26.412.0 7.5

While the ACCOLADE™ fluid or system (example drilling fluid of theinvention) was comprised of a mixture of the two tradename PETROFREE®esters and the tradename PETROFREE® SF base oil tested separately, theyield point of the example drilling fluid of the invention was lowerthan the yield point of any of those individual components or theiraverage. The ACCOLADE™ system's low yield point (1.6 Pa) is a reflectionof the “fragile” nature of the ACCOLADE™ system of the invention andcontributes to the excellent properties of that fluid of the invention.Further, these test results show a synergistic combination of the baseoils to give this low yield point.

Field-based fluids (as opposed to laboratory fluids or muds) may yieldvarying results in the tests above because of the presence of otherfluids, subterranean formation conditions, etc. Generally, experiencehas shown that the fluids of the invention often tend to yield betterresults in the field than in the lab. Some field test data will bepresented and discussed further below.

Test 3: Stress Build Function.

A test for distinguishing a drilling fluid of the invention using fieldmud samples is a performance measure called “Stress Build Function.”This measure is an indication of the structure building tendencies thatare effectively normalized for the initial yield stress (Tau0). Thismeasure also effectively normalizes for mud weight as well, sincegenerally higher weight fluids have higher Tau0 values. The “StressBuild Function” is defined as follows:SBF10m=(gel strength at 10 minutes−Tau0)/Tau0FIG. 11 shows data comparing the Stress Build Function for various fieldsamples of prior art fluids with the Stress Build Function for a fieldsample of an example fluid of the present invention, ACCOLADE™ system.The prior art fluids included PETROFREE® SF and a prior art internalolefin fluid. All of this data was taken at 120° F. using a FANN® 35, astandard six speed oilfield rheometer. Generally, a field mud of thepresent invention will have an SBF10m of greater than about 3.8. Fieldmuds having a SBF10m as low as about 3.0, however, can provide someadvantages of the invention.

While some organo-clay may enter the fluids in the field, for exampledue to mixing of recycled fluids with the fluids of the invention, thefluids of the invention are tolerant of such clay in quantities lessthan about 3 pounds per barrel, as demonstrated by the test data shownin Table 3 below. The fluids of the invention, however, behave more liketraditional drilling fluids when quantities greater than about 3 poundsper barrel of organo-clays are present. GELTONE® II additive used in thetest is a common organo-clay. TABLE 3 Effects of Addition ofOrgano-Clays to ACCOLADE ™ System Wt (lbs.) of GELTONE ® II additiveadded/bbl 11.0 ppg ACCOLADE ™ 0 1 2 3 4 τ (Pa) at 0.03 s⁻¹ 1.6 2.3 2.54.4 4.4 G′₁₀/G′₂₀₀ 24 14 10 1.0 1.0 (ratio of G′ at 10 s to G′ at 200 s)

Any drilling fluid that can be formulated to provide “fragile gel”behavior is believed to have the benefits of the present invention. Anydrilling fluid that can be formulated to have an elastic modulus ratioof G′₁₀/G′₂₀₀ greater than about 2 and/or a yield point measured asdescribed above less than about 3 Pa is believed to have the benefits ofthe present invention.

While the invert emulsion drilling fluids of the present invention havean invert emulsion base, this base is not limited to a singleformulation. Test data discussed herein for an example formulation of aninvert emulsion drilling fluid of the invention is for a drilling fluidcomprising a blend of one or more esters and one or more isomerized orinternal olefins (“ester blend”) such as described in U.S. patentapplication Ser. No. 09/929,465, of Jeff Kirsner (co-inventor of thepresent invention), Kenneth W. Pober and Robert W. Pike, filed Aug. 14,2001, entitled “Blends of Esters with Isomerized Olefins and OtherHydrocarbons as Base Oils for Invert Emulsion Oil Muds,” the entiredisclosure of which is incorporated herein by reference. In such blend,preferably the esters will comprise at least about 10 weight percent ofthe blend and may comprise up to about 99 weight percent of the blend,although the esters may be used in any quantity. Preferred esters forblending are comprised of about C₆ to about C₁₄ fatty acids andalcohols, and are particularly or more preferably disclosed in U.S. Pat.No. Re. 36,066, reissued Jan. 25, 1999 as a reissue of U.S. Pat. No.5,232,910, assigned to Henkel KgaA of Dusseldorf, Germany, and BaroidLimited of London, England, and in U.S. Pat. No. 5,252,554, issued Oct.12, 1993, and assigned to Henkel Kommanditgesellschaft auf Aktien ofDusseldorf, Germany and Baroid Limited of Aberdeen, Scotland, eachdisclosure of which is incorporated in its entirety herein by reference.Esters disclosed in U.S. Pat. No. 5,106,516, issued Apr. 21, 1992, andU.S. Pat. No. 5,318,954, issued Jun. 7, 1984, both assigned to HenkelKommanditgesellschaft auf Aktien, of Dusseldorf, Germany, eachdisclosure of which is incorporated in its entirety herein by reference,may also (or alternatively) be used. The most preferred esters for usein the invention are comprised of about C₁₂ to about C₁₄ fatty acids and2-ethyl hexanol or about C₈ fatty acids and 2-ethyl hexanol. These mostpreferred esters are available commercially under tradenames PETROFREE®and PETROFREE® LV, respectively, from Halliburton Energy Services, Inc.in Houston, Tex. Although esters made with fatty acids and alcohols arepreferred, esters made other ways, such as from combining olefins witheither fatty acids or alcohols, may also be effective.

Isomerized or internal olefins for blending with the esters for an esterblend may be any such olefins, straight chain, branched, or cyclic,preferably having about 10 to about 30 carbon atoms. Isomerized, orinternal, olefins having about 40 to about 70 weight percent C₁₆ andabout 20 to about 50 weight percent C₁₈ are especially preferred. Anexample of an isomerized olefin for use in an ester blend in theinvention that is commercially available is SF BASE™ fluid, availablefrom Halliburton Energy Services, Inc. in Houston, Tex. Alternatively,other hydrocarbons such as paraffins, mineral oils, glyceride triesters,or combinations thereof may be substituted for or added to the olefinsin the ester blend. Such other hydrocarbons may comprise from about 1weight percent to about 99 weight percent of such blend.

Invert emulsion drilling fluids may be prepared comprising SF BASE™fluid without the ester, however, such fluids are not believed toprovide the superior properties of fluids of the invention with theester. Field data discussed below has demonstrated that the fluids ofthe invention are superior to prior art isomerized olefin based drillingfluids, and the fluids of the invention have properties especiallyadvantageous in subterranean wells drilled in deep water. Moreover, theprinciples of the methods of the invention may be used with invertemulsion drilling fluids that form fragile gels or yield fragile gelbehavior, provide low ECDs, and have (or seem to have) viscoelasticitythat may not be comprised of an ester blend. One example of such a fluidmay comprise a polar solvent instead of an ester blend. Diesel oil maybe substituted for the ester provided that it is blended with a fluidthat maintains the viscosity of that blend near the viscosity ofpreferred ester blends of the invention such as the ACCOLADE™ system.For example, a polyalphaolefin (PAO), which may be branched orunbranched but is preferably linear and preferably ecologicallyacceptable (non-polluting oil) blended with diesel oil demonstrates someadvantages of the invention at viscosities approximating those of anACCOLADE™ fluid.

Other examples of possible suitable invert emulsion bases for thedrilling fluids of the present invention include isomerized olefinsblended with other hydrocarbons such as linear alpha olefins, paraffins,or naphthenes, or combinations thereof (“hydrocarbon blends”).

Paraffins for use in blends comprising invert emulsions for drillingfluids for the present invention may be linear, branched, poly-branched,cyclic, or isoparaffins, preferably having about 10 to about 30 carbonatoms. When blended with esters or other hydrocarbons such as isomerizedolefins, linear alpha olefins, or naphthenes in the invention, theparaffins should comprise at least about 1 weight percent to about 99weight percent of the blend, but preferably less than about 50 weightpercent. An example of a commercially available paraffin suited forblends useful in the invention is called tradename XP-07™ product,available from Halliburton Energy Services, Inc. in Houston, Tex. XP-07™is primarily a C₁₂₋₁₆ linear paraffin.

Examples of glyceride triesters for ester/hydrocarbon blends useful inblends comprising invert emulsions for drilling fluids for the presentinvention may include without limitation materials such as rapeseed oil,olive oil, canola oil, castor oil, coconut oil, corn oil, cottonseedoil, lard oil, linseed oil, neatsfoot oil, palm oil, peanut oil, perillaoil, rice bran oil, safflower oil, sardine oil, sesame oil, soybean oil,and sunflower oil.

Naphthenes or napthenic hydrocarbons for use in blends comprising invertemulsions for drilling fluids for the present invention may be anysaturated, cycloparaffinic compound, composition or material with achemical formula of C_(n)H_(2n) where n is a number about 5 to about 30.

In still another embodiment, a hydrocarbon blend might be blended withan ester blend to comprise an invert emulsion base for a drilling fluidof the present invention.

The exact proportions of the components comprising an ester blend (orother blend or base for an invert emulsion) for use in the presentinvention will vary depending on drilling requirements (andcharacteristics needed for the blend or base to meet thoserequirements), supply and availability of the components, cost of thecomponents, and characteristics of the blend or base necessary to meetenvironmental regulations or environmental acceptance. The manufactureof the various components of the ester blend (or other invert emulsionbase) is understood by one skilled in the art.

Further, the invert emulsion drilling fluids of the invention or for usein the present invention have added to them or mixed with their invertemulsion base, other fluids or materials needed to comprise completedrilling fluids. Such materials may include, for example: additives toreduce or control temperature rheology or to provide thinning, forexample, additives having the tradenames COLDTROL®, ATC®, and OMC2™;additives for enhancing viscosity, for example, an additive having thetradename RHEMOD L™; additives for providing temporary increasedviscosity for shipping (transport to the well site) and for use insweeps, for example, an additive having the tradename TEMPERUS™(modified fatty acid); additives for filtration control, for example, anadditive having the tradename ADAPTA®; additives for high temperaturehigh pressure control (HTHP) and emulsion stability, for example, anadditive having the tradename FACTANT™ (highly concentrated tall oilderivative); and additives for emulsification, for example, an additivehaving the tradename LE SUPERMUL™ (polyaminated fatty acid). All of theaforementioned trademarked products are available from HalliburtonEnergy Services, Inc. in Houston, Tex., U.S.A. Additionally, the fluidscomprise an aqueous solution containing a water activity loweringcompound, composition or material, comprising the internal phase of theinvert emulsion. Such solution is preferably a saline solutioncomprising calcium chloride (typically about 25% to about 30%, dependingon the subterranean formation water salinity or activity), althoughother salts or water activity lowering materials known in the art mayalternatively or additionally be used.

FIG. 10 compares the viscosity of a base fluid for comprising a drillingfluid of the present invention with known base fluids of some prior artinvert emulsion drilling fluids. The base fluid for the drilling fluidof the present invention is one of the thickest or most viscous. Yet,when comprising a drilling fluid of the invention, the drilling fluidhas low ECDs, provides good suspension of drill cuttings, satisfactoryparticle plugging and minimal fluid loss in use. Such surprisingadvantages of the drilling fluids of the invention are believed to befacilitated in part by a synergy or compatibility of the base fluid withappropriate thinners for the fluid.

Thinners disclosed in International patent application Nos.PCT/US00/35609 and PCT/US00/35610 of Halliburton Energy Services, Inc.,Cognis Deutschland GmbH & Co KG., Heinz Muller, Jeff Kirsner(co-inventor of the present invention) and Kimberly Burrows (co-inventorof the present invention), both filed Dec. 29, 2000 and entitled“Thinners for Invert Emulsions,” and both disclosures of which areincorporated entirely herein by reference, are particularly useful inthe present invention for effecting such “selective thinning” of thefluid of the present invention; that is thinning at lower temperatureswithout rendering the fluid too thin at higher temperatures. Suchthinners may have the following general formula:R—(C₂H₄O)_(n)(C₃H₆O)_(m)(C₄H₈O)_(k)—H (“formula I”), where R is asaturated or unsaturated, linear or branched alkyl radical having about8 to about 24 carbon atoms, n is a number ranging from about 1 to about10, m is a number ranging from about 0 to about 10, and k is a numberranging from about 0 to about 10. Preferably, R has about 8 to about 18carbon atoms; more preferably, R has about 12 to about 18 carbon atoms;and most preferably, R has about 12 to about 14 carbon atoms. Also, mostpreferably, R is saturated and linear.

The thinner may be added to the drilling fluid during initialpreparation of the fluid or later as the fluid is being used fordrilling or well service purposes in the subterranean formation. Thequantity of thinner added is an effective amount to maintain or effectthe desired viscosity of the drilling fluid. For purposes of thisinvention, the thinner of formula (I) is preferably from about 0.5 toabout 15 pounds per barrel of drilling fluid. A more preferred amount ofthinner ranges from about 1 to about 5 pounds per barrel of drillingfluid and a most preferred amount is about 1.5 to about 3 pounds thinnerper barrel of drilling fluid.

The compositions or compounds of formula (I) may be prepared bycustomary techniques of alkoxylation, such as alkoxylating thecorresponding fatty alcohols with ethylene oxide and/or propylene oxideor butylene oxide under pressure and in the presence of acidic oralkaline catalysts as is known in the art. Such alkoxylation may takeplace blockwise, i.e., the fatty alcohol may be reacted first withethylene oxide, propylene oxide or butylene oxide and subsequently, ifdesired, with one or more of the other alkylene oxides. Alternatively,such alkoxylation may be conducted randomly, in which case any desiredmixture of ethylene oxide, propylene oxide and/or butylene oxide isreacted with the fatty alcohol.

In formula (I), the subscripts n and m respectively represent the numberof ethylene oxide (EO) and propylene oxide (PO) molecules or groups inone molecule of the alkoxylated fatty alcohol. The subscript k indicatesthe number of butylene oxide (BO) molecules or groups. The subscripts n,m, and k need not be integers, since they indicate in each casestatistical averages of the alkoxylation. Included without limitationare those compounds of formula (I) whose ethoxy, propoxy, and/or butoxygroup distribution is very narrow, for example, “narrow rangeethoxylates” also called “NREs” by those skilled in the art.

The compound of formula (I) should contain at least one ethoxy group.Preferably, the compound of formula I will also contain at least onepropoxy group (C₃H₆O—) or butoxy group (C₄H₈O—). Mixed alkoxidescontaining all three alkoxide groups—ethylene oxide, propylene oxide,and butylene oxide—are possible for the invention but are not preferred.

Preferably, for use according to this invention, the compound of formula(I) will have a value for m ranging from about 1 to about 10 with k zeroor a value for k ranging from about 1 to about 10 with m zero. Mostpreferably, m will be about 1 to about 10 and k will be zero.

Alternatively, such thinners may be a non-ionic surfactant which is areaction product of ethylene oxide, propylene oxide and/or butyleneoxide with C₁₀₋₂₂ carboxylic acids or C₁₀₋₂₂ carboxylic acid derivativescontaining at least one double bond in position 9/10 and/or 13/14. Thesethinners may be used alone (without other thinners) or may be used incombination with a formula (I) thinner or with one or more commerciallyavailable thinners, including for example, products having thetradenames COLDTROL® (alcohol derivative), OMC2™ (oligomeric fattyacid), and ATC® (modified fatty acid ester), which themselves may beused alone as well as in combination, and are available from HalliburtonEnergy Services, Inc. in Houston, Tex., U.S.A. Blends of thinners suchas the OMC2™, COLDTROL®, and ATC® thinners can be more effective influids of the invention than a single one of these thinners.

The formulations of the fluids of the invention, and also theformulations of the prior art isomerized olefin based drilling fluids,used in drilling the boreholes cited in the field data below, vary withthe particular requirements of the subterranean formation. Table 4below, however, provides example formulations and properties for thesetwo types of fluids discussed in the field data below. All trademarkedproducts in Table 4 are available from Halliburton Energy Services, Inc.in Houston, Tex., including: LE MUL™ emulsion stabilizer (a blend ofoxidized tall oil and polyaminated fatty acid); LE SUPERMUL™ emulsifier(polyaminated fatty acid); DURATONE® HT filtration control agent(organophilic leonardite); ADAPTA® filtration control agent (copolymerparticularly suited for providing HPHT filtration control in non-aqueousfluid systems); RHEMOD L™ suspension agent/viscosifier (modified fattyacid); GELTONE® II viscosifier (organophilic clay); VIS-PLUS® suspensionagent (carboxylic acid); BAROID® weighting agent (ground bariumsulfate); and DEEP-TREAT® wetting agent/thinner (sulfonate sodium salt).In determining the properties in Table 4, samples of the fluids weresheared in a Silverson commercial blender at 7,000 rpm for 10 minutes,rolled at 150° F. for 16 hours, and stirred for 10 minutes. Measurementswere taken with the fluids at 120° F., except where indicated otherwise.TABLE 4 Isomerized Olefin Based ACCOLADE™ Invert Emulsion SystemDrilling Fluid A. Example Formulations Fluids and Compounds ACCOLADE ™Base (bbl) 0.590 — SF BASE ™ (bbl) — 0.568 LE MUL ™¹ (lb.) — 4 LESUPERMUL ™² (lb.) 10 6 Lime (lb.) 1 4 DURATONE ® HT³ (lb.) — 4Freshwater (bbl) 0.263 0.254 ADAPTA ®⁴ (lb.) 2 — RHEMOD L ™⁵ (lb.) 1 —GELTONE ® II⁶ (lb.) — 5 VIS-PLUS ®⁷ (lb.) — 1.5 BAROID ®⁸ (lb.) 138 138Calcium chloride (lb.) 32 31 DEEP-TREAT ®⁹ (lb.) — 2 B. PropertiesPlastic Viscosity (cP) 19 19 Yield Point (lb/100 ft²) 13 14 10 secondgel (lb/100 ft²) 9 7 10 minute gel (lb/100 ft²) 12 9 HPHT Temperature (°F.) 225 200 HPHT @ 500 psid (mL) 0.8 1.2 Electrical stability (volts)185 380 FANN ® 35 Dial Readings: 600 rpm 51 52 300 rpm 32 33 200 rpm 2526 100 rpm 18 18  6 rpm 7 7  3 rpm 5 6¹Blend of oxidized tall oil and polyaminated fatty acid emulsionstabilizer.²Polyaminated fatty acid emulsifier.³Organophilic leonardite filtration control agent.⁴Copolymer HTHP filtration control agent for non-aqueous systems.⁵Modified fatty acid suspension agent/viscosifier.⁶Organophilic clay viscosifier.⁷Carboxylic acid suspension agent.⁸Ground barium sulfate weighting agent.⁹Sulfonate sodium salt wetting agent/thinner.

The invert emulsion drilling fluids of the present invention preferablydo not have any organophilic clays added to them. The fluids of theinvention do not need organophilic clays or organophilic lignites toprovide their needed viscosity, suspension characteristics, orfiltration control to carry drill cuttings to the well surface.Moreover, the lack of appreciable amounts of organophilic clays andorganophilic lignites in the fluids is believed to enhance the toleranceof the fluids to the drill cuttings. That is, the lack of appreciableamounts of organophilic clays and organophilic lignites in the fluids ofthe invention is believed to enable the fluids to suspend and carrydrill cuttings without significant change in the fluids' rheologicalproperties.

Experimental

The present invention provides a drilling fluid with a relatively flatrheological profile. Table 5 provides example rheological data for adrilling fluid of the invention comprising 14.6 ppg of a tradenameACCOLADE™ system. TABLE 5 ACCOLADE ™ System Downhole Properties FANN ®75 Rheology 14.6 ppg ACCOLADE ™ System Temp. (° F.) 120 40 40 40 80 210230 250 270 Pressure 0 0 3400 6400 8350 15467 16466 17541 18588 600 rpm67 171 265 325 202 106 98 89 82 300 rpm 39 90 148 185 114 63 58 52 48200 rpm 30 64 107 133 80 49 45 40 37 100 rpm 19 39 64 78 47 32 30 27 25 6 rpm 6 6 10 11 11 8 9 8 8  3 rpm 5 6 10 11 11 8 9 8 8 Plastic 28 81117 140 88 43 40 37 34 Viscosity (cP) Yield Point 11 9 31 45 26 20 18 1514 (lb/100 ft²) N 0.837 0.948 0.869 0.845 0.906 0.799 0.822 0.855 0.854K 0.198 0.245 0.656 0.945 0.383 0.407 0.317 0.226 0.21 Tau 0 4.68 6.078.29 8.12 9.68 7.45 8.21 8.29 7.75 (lb/100 ft²As used in Table 5 “N” and “K” are Power Law model rheology parameters.

FIGS. 9(b) and (c) compare the effect of temperature on pressuresobserved with two different fluid weights (12.1 and 12.4 ppg) whenapplying six different and increasing shear rates (3, 6, 100, 200, 300,and 600 rpm). Two common testing temperatures were used—40° F. and 120°F. The change in temperature and fluid weight resulted in minimal changein fluid behavior. FIG. 9(a) compares the yield point of two differentweight formulations (12.1 ppg and 12.4 ppg) of a fluid of the presentinvention at two different temperatures (40° F. and 120° F.). The yieldpoint is unexpectedly lower at 40° F. than at 120° F. Prior artoil-based fluids typically have lower yield points at highertemperatures, as traditional or prior art oils tend to thin or havereduced viscosity as temperatures increase. In contrast, the fluids ofthe invention can be thinned at lower temperatures without significantlyaffecting the viscosity of the fluids at higher temperatures. Thisfeature or characteristic of the invention is a further indicator thatthe invention will provide good performance as a drilling fluid and willprovide low ECDs. Moreover, this characteristic indicates the ability ofthe fluid to maintain viscosity at higher temperatures. The preferredtemperature range for use of an ACCOLADE™ system extends from about 40°F. to about 350° F. The preferred mud weight for an ACCOLADE™ systemextends from about 9 ppg to about 17 ppg.

Field Tests

The present invention has been tested in the field and the field datademonstrates the advantageous performance of the fluid compositions ofthe invention and the methods of using them. As illustrated in FIGS.1(a), (b), (c), and 2, the present invention provides an invert emulsiondrilling fluid that may be used in drilling boreholes or wellbores insubterranean formations, and in other drilling operations in suchformations (such as in casing and cementing wells), without significantloss of drilling fluid when compared to drilling operations with priorart fluids.

FIGS. 1(a), (b), and (c) show three graphs comparing the actual fluidloss experienced in drilling 10 wells in the same subterraneanformation. In nine of the wells, an isomerized olefin based fluid (inthis case, tradename PETROFREE® SF available from Halliburton EnergyServices, Inc. in Houston, Tex.), viewed as an industry “standard” forfull compliance with current environmental regulations, was used. In onewell, a tradename ACCOLADE™ system, a fluid having the features orcharacteristics of the invention and commercially available fromHalliburton Energy Services, Inc. in Houston, Tex. (and also fullycomplying with current environmental regulations) was used. The holedrilled with an ACCOLADE™ system was 12.25 inches in diameter. The holesdrilled with the “standard” tradename PETROFREE® SF fluid were about 12inches in diameter with the exception of two sidetrack holes that wereabout 8.5 inches in diameter. FIG. 1(a) shows the total number ofbarrels of fluid lost in drilling, running, casing and cementing theholes. FIG. 1(b) shows the total number of barrels of fluid lost perbarrel of hole drilled. FIG. 1 (c) shows the total number of barrels offluid lost per foot of well drilled, cased or cemented. For each ofthese wells graphed in these FIGS. 1 (a), (b) and (c), the drillingfluid lost when using a fluid of the invention was remarkably lower thanwhen using the prior art fluid.

FIG. 2 compares the loss of fluid with the two drilling fluids inrunning casing and cementing at different well depths in the samesubterranean formation. The prior art isomerized olefin based fluid wasused in the first three wells shown on the bar chart and a fluid of thepresent invention was used in the next four wells shown on the barchart. Again, the reduction in loss of fluid when using the fluid of thepresent invention was remarkable.

The significant reduction in fluid loss seen with the present inventionis believed to be due at least in substantial part to the “fragile gel”behavior of the fluid of the present invention and to the chemicalstructure of the fluid that contributes to, causes, or results in thatfragile gel behavior. According to the present invention, fluids havingfragile gel behavior provide significant reduction in fluid lossesduring drilling (and casing and cementing) operations when compared tofluid losses incurred with other drilling fluids that do not havefragile gel behavior. Thus, according to the methods of the invention,drilling fluid loss may be reduced by employing a drilling fluid indrilling operations that is formulated to comprise fragile gels or toexhibit fragile gel behavior. As used herein, the term “drillingoperations” shall mean drilling, running casing and/or cementing unlessindicated otherwise.

FIG. 3 represents in graphical form data indicating gel formation insamples of two different weight (12.65 and 15.6 ppg) ACCOLADE® fluids ofthe present invention and two comparably weighted (12.1 and 15.6 ppg)prior art invert emulsion fluids (tradename PETROFREE® SF) at 120° F.When the fluids are at rest or static (as when drilling has stopped inthe wellbore), the curves are flat or relatively flat (see area at about50-65 minutes elapsed time for example). When shear stress is resumed(as in drilling), the curves move up straight vertically or generallyvertically (see area at about 68 to about 80 elapsed minutes forexample), with the height of the curve being proportional to the amountof gel formed—the higher the curve the more gel built up. The curvesthen fall down and level out or begin to level out, with the faster rateat which the horizontal line forms (and the closer the horizontal lineapproximates true horizontal) indicating the lesser resistance of thefluid to the stress and the lower the pressure required to move thefluid.

FIG. 3 indicates superior response and performance by the drillingfluids of the present invention. Not only do the fluids of the presentinvention appear to build up more “gel” when at rest, which enables thefluids of the invention to better maintain weight materials and drillcuttings in suspension when at rest—a time prior art fluids are morelikely to have difficulty suspending such solid materials—but the fluidsof the present invention nevertheless surprisingly provide lessresistance to the sheer, which will result in lower ECDs as discussedfurther herein.

FIG. 4 provides data further showing the gel or gel-like behavior of thefluids of the present invention. FIG. 4 is a graph of the relaxationrates of various drilling fluids, including fluids of the presentinvention and prior art isomerized olefin based fluids. In the test,conducted at 120° F., the fluids are exposed to stress and then thestress is removed. The time required for the fluids to relax or toreturn to their pre-stressed state is recorded. The curves for thefluids of the invention seem to level out over time whereas the priorart fluids continue to decline. The leveling out of the curves arebelieved to indicate that the fluids are returning to a true gel orgel-like structure.

The significant reduction in fluid loss seen with the present inventioncan be due in substantial part to the viscoelasticity of the fluids ofthe present invention. Such viscoelasticity, along with the fragile gelbehavior, is believed to enable the fluids of the invention to minimizethe difference in its density at the surface and its equivalentcirculating density downhole.

Table 10 below and FIG. 5(a) showing the Table 10 data in graph formillustrate the consistently stable and relatively minimal difference inequivalent circulating density and actual fluid weight or well surfacedensity for the fluids of the invention. This minimal difference isfurther illustrated in FIG. 5(a) and in Table 10 by showing theequivalent circulating density downhole for a commercially availableisomerized olefin drilling fluid in comparison to a drilling fluid ofthe present invention. Both fluids had the same well surface density.The difference in equivalent circulating density and well surfacedensity for the prior art fluid however was consistently greater thansuch difference for the fluid of the invention. FIG. 5(b) provides therates of penetration or drilling rates at the time the measurementsgraphed in FIG. 5(a) were made. FIG. 5(b) indicates that the fluid ofthe invention provided its superior performance—low—ECDs at surprisinglyfaster drilling rates, making its performance even more impressive, asfaster drilling rates tend to increase ECDs with prior art fluids. TABLE10 Comparison of Equivalent Circulating Densities PWD Data PWD DataACCOLADE ™ Isomerized Olefin System based fluid pump rate: 934 gpm MudWeight pump rate: 936 gpm DEPTH BIT: 12.25″ At well surface BIT: 12.25″(in feet) (ppg) (ppg) (ppg) 10600 12.29 12.0 12.51 10704 12.37 12.012.53 10798 12.52 12.0 12.72 10,899 12.50 12.2 12.70 11,001 12.50 12.212.64 11,105 12.52 12.2 12.70 11,200 12.50 12.2 12.69 11,301 12.55 12.212.70 11,400 12.55 12.2 12.71 11,500 12.59 12.2 12.77 11,604 12.59 12.212.79 11,700 12.57 12.2 12.79 11,802 12.60 12.2 12.79 11,902 12.62 12.212.81 12,000 12.64 12.2 12.83 12,101 12.77 12.2 12.99 12,200 12.77 12.312.99 12,301 12.76 12.3 13.01

FIG. 6 graphs the equivalent circulating density of an ACCOLADE™ system,as measured downhole during drilling of a 12¼ inch borehole from 9,192feet to 13,510 feet in deepwater (4,900 feet), pumping at 704 to 811gallons per minute, and compares it to the fluid's surface density. Rateof penetration (“ROP”) (or drilling rate) is also shown. This datafurther shows the consistently low and stable ECDs for the fluid,notwithstanding differences in the drilling rate and consequently thedifferences in stresses on the fluid.

FIG. 7 similarly graphs the equivalent circulating density of anACCOLADE™ system, as measured downhole during drilling of a 6½ inchborehole from 12,306 feet to 13,992 feet, pumping at 158 to 174 gallonsper minute in deepwater, and compares it to the fluid's surface density.Rate of penetration (or drilling rate) is also shown. Despite therelatively erratic drilling rate for this well, the ECDs for thedrilling fluid were minimal, consistent, and stable. Comparing FIG. 7 toFIG. 6 shows that despite the narrower borehole in FIG. 7 (6½ inchescompared to the 12¼ inch borehole for which data is shown in FIG. 6),which would provide greater stress on the fluid, the fluid performanceis effectively the same.

FIG. 8 graphs the equivalent circulating density of an ACCOLADE™ system,as measured downhole during drilling of a 9⅞ inch borehole from 4,672feet to 12,250 feet in deepwater, pumping at 522 to 585 gallons perminute, and compares it to the surface density of the fluid and the rateof penetration (“ROP”) (or drilling rate). The drilling fluid providedlow, consistent ECDs even at the higher drilling rates.

Environmental Impact Studies

Table 11 and the graph in FIG. 12 summarize results of an environmentalimpact 10-day Leptocheirus test. TABLE 11 Synthetic Based FluidsBioassay Using 960 Hour Sediment Toxicity Test With Leptocheirusplumulosus Target 96-Hour 95% Sample Component LC₅₀ (ml/Kg dryConfidence % Control ID Carrier sediment) Interval Survival A 11.5 ppg77 63-93 95 Revised API Reference IO SBM B 11.5 ppg 134 117-153 95ACCOLADE ™ SBM (lab prep.) C 14.0 ppg 98  74-130 97 ACCOLADE ™ (Field 1)D 13.7 ppg 237 189-298 98 ACCOLADE ™ (Field 2) E 11.4 ppg 319 229-443 97ACCOLADE ™ (Field 3) F 17.5 ppg 269 144-502 97 ACCOLADE ™ (Field 4)As used in Table 11, the abbreviation “IO” refers to the referenceisomerized olefin cited in the test, and the abbreviation “SBM” refersto a “synthetic based mud.” “SBM” is used in Table 11 to helpdistinguish laboratory formulations prepared for testing from field mudsamples collected for testing (although the field muds also have asynthetic base). The data shows that the ACCOLADE™ samples providedenhanced compatibility with Leptocheirus, exceeding the minimum requiredby government regulations. The test was conducted according to the ASTME 1367-99 Standard Guide for Conducting 10-day Static Sediment ToxicityTests with Marine and Estuarine Amphipods, ASTM, 1997 (2000). The methodof the test is also described in EPA Region 6. Final NPEDS GeneralPermit for New and Existing Sources and New Discharges in the OffshoreSubcategory of the Outer Continental Shelf of the Gulf of Mexico (GMG290000); Appendix A, Method for Conducting a Sediment Toxicity Test withLeptocheirus plumulosus and Non-Aqueous Fluids or Synthetic BasedDrilling Fluids (Effective February, 2002). Further, the ACCOLADE™samples were found to meet and exceed the biodegradability requirementsset forth by the United States Environmental Protection Agency.

As indicated above, the advantages of the methods of the invention maybe obtained by employing a drilling fluid of the invention in drillingoperations. The drilling operations—whether drilling a vertical ordirectional or horizontal borehole, conducting a sweep, or runningcasing and cementing—may be conducted as known to those skilled in theart with other drilling fluids. That is, a drilling fluid of theinvention is prepared or obtained and circulated through a wellbore asthe wellbore is being drilled (or swept or cemented and cased) tofacilitate the drilling operation. The drilling fluid removes drillcuttings from the wellbore, cools and lubricates the drill bit, aids insupport of the drill pipe and drill bit, and provides a hydrostatic headto maintain the integrity of the wellbore walls and prevent wellblowouts. The specific formulation of the drilling fluid in accordancewith the present invention is optimized for the particular drillingoperation and for the particular subterranean formation characteristicsand conditions (such as temperatures). For example, the fluid isweighted as appropriate for the formation pressures and thinned asappropriate for the formation temperatures. As noted previously, thefluids of the invention afford real-time monitoring and rapid adjustmentof the fluid to accommodate changes in such subterranean formationconditions. Further, the fluids of the invention may be recycled duringa drilling operation such that fluids circulated in a wellbore may berecirculated in the wellbore after returning to the surface for removalof drill cuttings for example. The drilling fluid of the invention mayeven be selected for use in a drilling operation to reduce loss ofdrilling mud during the drilling operation and/or to comply withenvironmental regulations governing drilling operations in a particularsubterranean formation.

The foregoing description of the invention is intended to be adescription of preferred embodiments. Various changes in the details ofthe described fluids and methods of use can be made without departingfrom the intended scope of this invention as defined by the appendedclaims.

1. A method for drilling in a subterranean formation comprising:providing or using an invert emulsion drilling fluid having a G′10/G′200elastic modulus ratio greater than about 2 and/or a yield point lessthan about 3 Pa at a shear rate of about 3.0 s−1 or less.
 2. The methodof claim 1 wherein the drilling fluid comprises: an invert emulsionbase; an emulsifier; a weighting agent; a rheology modifier; afiltration control agent; and optionally, organophilic clay present inan amount from about 0 to about 3 pounds per barrel.
 3. The method ofclaim 2 wherein the invert emulsion base comprises at least onecomponent selected from one of the groups consisting of: (i) estersprepared from fatty acids and alcohols, esters prepared from olefins andfatty acids or alcohols; (ii) olefins comprising linear alpha olefins,isomerized olefins having a straight chain, olefins having a branchedstructure, isomerized olefins having a cyclic structure; olefinhydrocarbons; (iii) paraffin hydrocarbons comprising linear paraffins,branched paraffins, poly-branched paraffins, cyclic paraffins,isoparaffins; (iv) mineral oil hydrocarbons; (v) glyceride triesterscomprising rapeseed oil, olive oil, canola oil, castor oil, coconut oil,corn oil, cottonseed oil, lard oil, linseed oil, neatsfoot oil, palmoil, peanut oil, perilla oil, rice bran oil, safflower oil, sardine oil,sesame oil, soybean oil, sunflower oil; (vi) naphthenic hydrocarbons;and (vii) combinations thereof.
 4. The method of claim 2 wherein theinvert emulsion base comprises an internal olefin.
 5. The method ofclaim 2 wherein the invert emulsion base is substantially ester-free. 6.The method of claim 2 wherein the invert emulsion base comprises anester and an olefin.
 7. The method of claim 2 wherein the rheologymodifier comprises a modified fatty acid.
 8. The method of claim 2wherein the filtration control agent comprises a copolymer.
 9. Themethod of claim 2 wherein the rheology modifier comprises a modifiedfatty acid and the filtration control agent comprises a copolymer. 10.The method of claim 2 wherein the invert emulsion base comprises aninternal olefin, the rheology modifier comprises a modified fatty acidand the filtration control agent comprises a copolymer.
 11. The methodof claim 2 wherein the organophilic clay is present in an amount fromabout 0 to about 1 pound per barrel.
 12. The method of claim 2 whereinthe organophilic clay is present in an amount from about 1 to about 3pounds per barrel.
 13. The method of claim 1 wherein the drilling fluidis substantially free of lignite.
 14. The method of claim 1 wherein thedrilling fluid is substantially free of an organophilic filtrationcontrol agent.
 15. The method of claim 1 wherein the drilling fluid isused in the temperature range of from about 40° F. to about 120° F. 16.The method of claim 1 wherein the drilling fluid has a lower yield pointat a temperature of about 40° F. than at a temperature of about 120° F.17. The method of claim 1 wherein an equivalent circulating density ofthe drilling fluid approximates a surface density of the drilling fluid.18. The method of claim 1 wherein the drilling fluid is used offshore.19. The method of claim 1 wherein the drilling fluid is tolerant todrill cuttings.
 20. The method of claim 1 wherein the drilling fluiddoes not exhibit significant sag when at rest.
 21. The method of claim 1wherein the drilling fluid is used in drilling a well with loss of thedrilling fluid being less than about 1 barrel per barrel of holedrilled.
 22. The method of claim 1 wherein the drilling fluid is used inrunning casing and cementing with loss of the drilling fluid being lessthan about 100 barrels of total drilling fluid.
 23. The method of claim1 wherein the drilling fluid is used in drilling, running casing andcementing with loss of the drilling fluid being less than about 500barrels of total drilling fluid.
 24. The method of claim 1 wherein thedrilling fluid further comprises a thinner.
 25. The method of claim 1wherein the drilling fluid further comprises a thinner that reduces theviscosity of the drilling fluid at about 40° F. to a greater extent thanit reduces the viscosity of the drilling fluid at about 120° F.
 26. Themethod of claim 1 wherein the drilling fluid further comprises one ormore additives selected from the group consisting of an emulsionstabilizer, a viscosifier, an HTHP additive, and a water activitylowering material.
 27. The method of claim 1 wherein the shear rate is0.03 s−1.
 28. The method of claim 1 wherein the shear rate is 0.1 s−1.29. The method of claim 1 wherein the shear rate is 1.0 s−1.
 30. Themethod of claim 1 wherein the drilling fluid has a Stress Build Functiongreater than about 3.0.
 31. The method of claim 1 further comprisingdrilling, running casing and/or cementing a wellbore in the subterraneanformation.
 32. A drilling fluid for drilling in a subterranean formationcomprising an invert emulsion drilling fluid having a G′10/G′200 elasticmodulus ratio greater than about 2 and/or a yield point less than about3 Pa at a shear rate of about 3.0 s−1 or less.
 33. The drilling fluidclaim 32 wherein the drilling fluid comprises: an invert emulsion base;an emulsifier; a weighting agent; a rheology modifier; a filtrationcontrol agent; and optionally, organophilic clay present in an amountfrom about 0 to about 3 pounds per barrel.
 34. The drilling fluid ofclaim 33 wherein the invert emulsion base comprises at least onecomponent selected from one of the groups consisting of: (i) estersprepared from fatty acids and alcohols, esters prepared from olefins andfatty acids or alcohols; (ii) olefins comprising linear alpha olefins,isomerized olefins having a straight chain, olefins having a branchedstructure, isomerized olefins having a cyclic structure; olefinhydrocarbons; (iii) paraffin hydrocarbons comprising linear paraffins,branched paraffins, poly-branched paraffins, cyclic paraffins,isoparaffins; (iv) mineral oil hydrocarbons; (v) glyceride triesterscomprising rapeseed oil, olive oil, canola oil, castor oil, coconut oil,corn oil, cottonseed oil, lard oil, linseed oil, neatsfoot oil, palmoil, peanut oil, perilla oil, rice bran oil, safflower oil, sardine oil,sesame oil, soybean oil, sunflower oil; (vi) naphthenic hydrocarbons;and (vii) combinations thereof.
 35. The drilling fluid of claim 33wherein the invert emulsion base comprises an internal olefin.
 36. Thedrilling fluid of claim 33 wherein the invert emulsion base issubstantially ester-free.
 37. The drilling fluid of claim 33 wherein theinvert emulsion base comprises an ester and an olefin.
 38. The drillingfluid of claim 33 wherein the rheology modifier comprises a modifiedfatty acid.
 39. The drilling fluid of claim 33 wherein the filtrationcontrol agent comprises a copolymer.
 40. The drilling fluid of claim 33wherein the rheology modifier comprises a modified fatty acid and thefiltration control agent comprises a copolymer.
 41. The drilling fluidof claim 33 wherein the invert emulsion base comprises an internalolefin, the rheology modifier comprises a modified fatty acid and thefiltration control agent comprises a copolymer.
 42. The drilling fluidof claim 33 wherein the organophilic clay is present in an amount fromabout 0 to about 1 pound per barrel.
 43. The drilling fluid of claim 33wherein the organophilic clay is present in an amount from about 1 toabout 3 pounds per barrel.
 44. The drilling fluid of claim 32 whereinthe drilling fluid is substantially free of lignite.
 45. The drillingfluid of claim 32 wherein the drilling fluid is substantially free of anorganophilic filtration control agent.
 46. The drilling fluid of claim32 wherein the drilling fluid is used in the temperature range of fromabout 40° F. to about 120° F.
 47. The drilling fluid of claim 32 whereinthe drilling fluid has a lower yield point at a temperature of about 40°F. than at a temperature of about 120° F.
 48. The drilling fluid ofclaim 32 wherein an equivalent circulating density of the drilling fluidapproximates a surface density of the drilling fluid.
 49. The drillingfluid of claim 32 wherein the drilling fluid is used offshore.
 50. Themethod of claim 36 wherein the drilling fluid is tolerant to drillcuttings.
 51. The drilling fluid of claim 32 wherein the drilling fluiddoes not exhibit significant sag when at rest.
 52. The drilling fluid ofclaim 32 wherein the drilling fluid is used in drilling a well with lossof the drilling fluid being less than about 1 barrel per barrel of holedrilled.
 53. The drilling fluid of claim 32 wherein the drilling fluidis used in running casing and cementing with loss of the drilling fluidbeing less than about 100 barrels of total drilling fluid.
 54. Thedrilling fluid of claim 32 wherein the drilling fluid is used indrilling, running casing and cementing with loss of the drilling fluidbeing less than about 500 barrels of total drilling fluid.
 55. Thedrilling fluid of claim 32 wherein the drilling fluid further comprisesa thinner.
 56. The drilling fluid of claim 32 wherein the drilling fluidfurther comprises a thinner that reduces the viscosity of the drillingfluid at about 40° F. to a greater extent than it reduces the viscosityof the drilling fluid at about 120° F.
 57. The drilling fluid of claim32 wherein the drilling fluid further comprises one or more additivesselected from the group consisting of an emulsion stabilizer, aviscosifier, an HTHP additive, and a water activity lowering material.58. The drilling fluid of claim 32 wherein the shear rate is 0.03 s−1.59. The drilling fluid of claim 32 wherein the shear rate is 0.1 s−1.60. The drilling fluid of claim 32 wherein the shear rate is 1.0 s−1.61. The drilling fluid of claim 32 wherein the drilling fluid has aStress Build Function greater than about 3.0.
 62. The drilling fluid ofclaim 32 wherein the drilling fluid is used in drilling, running casingand/or cementing a wellbore in the subterranean formation.